Conventional drilling can be performed with Coil Tubing (CTD) or with Jointed Pipes (JPD). CTD can be described as drilling with a continuous pipe coiled onto a reel. It is associated with a downhole drilling motor that provides rotation to the bit. JPD uses jointed drill pipes which can either be rotated from surface or have a downhole drilling motor to rotate the bit.
In both CTD and JPD techniques, the drillstring (CT or pipes) provides the weight on bit (WOB) transfer from surface to downhole. Downhole drilling efficiency is therefore dependant on the full drillstring transfer function (frictional losses, drag effect, vibrations . . . ). Various surface and downhole sensors collect data and send them to a surface processor for monitoring. Drilling and steering commands are then applied from surface.
Various proposals have been made to address a market need such as extended reach or short radius drilling, in which the bottom hole assembly is designed to perform new functions such as generating the weight and the torque on bit downhole, while the drill string and surface rig functionality are reduced. No mechanical power transmission from surface to downhole is used, thereby reducing drilling efficiency losses due to the drill string transfer function. The power can be conveyed from surface to downhole via an electrical or hydraulic link (wireline, wired drill pipes, hydraulic pump at surface with downhole turbine, etc.). The electrical power is then converted downhole into mechanical power at the bit via an electrical drilling motor and a thruster to generate the WOB.
The methods and systems used for monitoring drilling and steering currently proposed for electrical drilling are usually the same used for conventional drilling. They have not yet taken the advantages presented by the electrical drilling machines and are currently derived from various characteristics inherent only to CTD and JPD, for example:                The drilling process is controlled from surface in order to drill a borehole and control its direction.        Various sensors and actuators are at surface, for example WOB is controlled from surface.        The drillstring mechanical motion and its interface with the wellbore and casing string is a major contributor to the drilling dynamics.        The mechanical power injected at surface is very high.        It is not possible to measure precisely the depth and ROP of the drill bit due to the drill pipe and coil tuning flexion under the WOB.        It is not possible to control the instantaneous ROP of the bit. Control is done by applying a constant WOB at surface and monitoring the TOB and ROP.        The two-way telemetry from surface to downhole has a limited bandwidth.        The BHA design changes from one well to another.        Downhole drilling parameters WOB, TOB and RPM are impacted by many factors such as the length of the drillstring, well profile, rock bit interaction, tubing/borehole frictions, BHA layout.        The drilling strategy is based on a surface WOB control with a fixed bit RPM. Obtained ROP depends on the formation strengths and lithology encountered.        
The drilling commands of WOB, RPM are set at surface in all conventional drilling systems. Many systems propose using surface models to predict the drilling behavior and therefore assist the driller optimize the drilling and steering process. These have as inputs data from downhole sensors sent via a telemetry system as well as surface sensor parameters. Examples can be found in U.S. Pat. Nos. 6,732,052, 4,733,733, and 4,854,397.
Other systems in conventional drilling allow dynamically adjustment of the surface parameters in order to maximize the drilling efficiency, for example many rigs have a dynamic control of RPM or torque on a top drive in order to attenuate the torsional vibrations of the drill string. Other mechanisms have been developed to be included in the BHA and that either passively or actively try to attenuate torque, WOB or RPM fluctuations.
With regard to current directional drilling techniques, all existing techniques rely on two way communication from surface. One limitation of full automating the steering downhole in conventional drilling is that the information of bit depth is measured at surface. Also the directional behavior of the hole will depend on many factors such as WOB, and drillstring behavior. Examples can be found in U.S. Pat. No. 6,467,557, WO 2005/028805, and WO 93/12318. U.S. Pat. No. 6,490,527 discloses a method and system for determining the relative strength and classification of rock strata using neural networks applied on conventional drilling. One of the limitations of the technique is that the data collected by the sensors to calculate the specific energy of the rock are not only representative of the formation but also account partly for the behavior of the drillstring. Also, phenomena such as bit balling can not be detected properly in real time such that subsequent drilling data may be wrongly interpreted. Some studies have been developed to solve some of these limitation but the techniques stay limited due to the high number of uncertainty (see IADC/SPE 47799).
While there have been various proposals for electrical drilling machines, none of them present methods of drilling that takes advantage of the fact that all actuators and sensors relative to drilling are located downhole. Examples of the existing techniques include U.S. Pat. Nos. 4,051,908, 6,305,469, US-2005-0252688, WO 20041083595, EP0911483, SPE 60750, U.S. Pat. No. 6,467,557, WO 2004/011766, U.S. Pat. Nos. 6,142,235, 6,629,570. GB2388132, and U.S. Pat. No. 6,629,568.
All of the existing techniques rely on a WOB or ROP control at surface to optimize the drilling process. At a given ROP, many depths of cut are possible depending on bit RPM. Having a constant DOC is not equivalent to having a constant ROP. DOC can be limited in conventional drilling by bit design. However, DOC cannot be controlled by the drilling process because of BHA dynamics and the lack of a precise DOC measurement precision. EP1780372 discloses a method of drilling using DOC as a controlled parameter. However, controlling DOC is not always the best way to optimize a drilling process. The present invention is intended to address this fact.